Systems and methods for enhancing steam distribution and production in sagd operations

ABSTRACT

A system for recovering hydrocarbons from a subterranean formation with steam-assisted gravity drainage (SAGD) includes a steam injection well. The steam injection well includes a first portion extending from the surface through an unconsolidated layer of the formation to a consolidated layer of the formation, a second portion extending horizontally through the consolidated layer, and a plurality of third portions extending from the second portion. Each third portion extends upward from the second portion into the unconsolidated layer of the formation and a hydrocarbon reservoir in the unconsolidated layer of the formation. In addition, the system includes a production well. The production well includes a first portion extending from the surface through the unconsolidated and a second portion extending horizontally through the unconsolidated layer. The second portion of the production well is vertically positioned above the second portion of the steam injection well.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority, under 35 U.S.C. §119(e), of Provisional Application No. 61/887,487, filed Oct. 7, 2013, incorporated herein by this reference.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

This disclosure relates generally to steam-assisted gravity drainage (SAGD) techniques for producing viscous hydrocarbons from subterranean formations. More particularly, the invention relates to the use of a steam injection well including a horizontal portion extending through a consolidated formation and a plurality of secondary portions extending upward from the horizontal portion into an unconsolidated formation containing a hydrocarbon reservoir to enhance steam distribution and associated production.

As existing reserves of conventional light liquid hydrocarbons (e.g., light crude oil) are depleted and prices for hydrocarbon products continue to rise, there is a push to find new sources of hydrocarbons. Viscous hydrocarbons such as heavy oil and bitumen offer an alternative source of hydrocarbons with extensive deposits throughout the world. In general, hydrocarbons having an API gravity less than 22° are referred to as “heavy oil” and hydrocarbons having an API gravity less than 10° are referred to as “bitumen.” Although recovery of heavy oil and bitumen present challenges due to their relatively high viscosities, there are a variety of processes that can be employed to recover such viscous hydrocarbons from underground deposits.

Many techniques for recovering heavy oil and bitumen utilize thermal energy to heat the hydrocarbons, decrease the viscosity of the hydrocarbons, and mobilize the hydrocarbons within the formation, thereby enabling the extraction and recovery of the hydrocarbons. Accordingly, such production and recovery processes may generally be described as “thermal” techniques. A steam-assisted gravity drainage (SAGD) operation is one thermal technique for recovering viscous hydrocarbons such as bitumen and heavy oil. SAGD operations typically employ two vertically spaced horizontal wells drilled into the formation and through the reservoir of interest. Steam is injected into the formation via the upper well, typically referred to as the “injection well,” to form a steam chamber that extends radially outward and upward from the injection well. Thermal energy from the steam reduces the viscosity of the viscous hydrocarbons in the reservoir, thereby enabling them to flow downward through the formation under the force of gravity. The mobilized hydrocarbons drain into the lower well, typically referred to as the “production well.” The hydrocarbons collected in the production well are produced to the surface with artificial lift techniques.

BRIEF SUMMARY OF THE DISCLOSURE

These and other needs in the art are addressed in one embodiment by a system for recovering hydrocarbons from a subterranean formation with steam-assisted gravity drainage (SAGD). The formation includes an unconsolidated layer containing a hydrocarbon reservoir and a consolidated layer disposed below the unconsolidated layer. In an embodiment, the system comprises a steam injection well including a first portion extending from the surface through the unconsolidated layer to the consolidated layer, a second portion extending horizontally through the consolidated layer, and a plurality of third portions extending from the second portion. Each third portion extends upward from the second portion into the unconsolidated layer of the formation and the hydrocarbon reservoir. In addition, the system comprises a production well including a first portion extending from the surface through the unconsolidated layer and a second portion extending horizontally through the unconsolidated layer. The second portion of the production well is vertically positioned above the second portion of the steam injection well.

These and other needs in the art are addressed in another embodiment by a method for producing hydrocarbons from a subterranean formation with steam-assisted gravity drainage (SAGD). The formation includes an unconsolidated layer containing a hydrocarbon reservoir and a consolidated layer disposed below the unconsolidated layer. In an embodiment, the method comprises (a) drilling a first portion of a steam injection well through the consolidated layer of the formation. In addition, the method comprises (b) drilling a plurality of second portions of a steam injection well upward from the first portion of the steam injection well into the unconsolidated layer. Further, the method comprises (c) drilling a first portion of a production well through the unconsolidated layer of the formation.

These and other needs in the art are addressed in another embodiment by a method for producing hydrocarbons from a subterranean formation with steam-assisted gravity drainage (SAGD). The formation includes an unconsolidated layer containing a hydrocarbon reservoir and a consolidated layer disposed below the unconsolidated layer. In an embodiment, the method comprises (a) flowing steam from the surface through a subterranean steam injection well extending through the unconsolidated layer of the formation and into the consolidated layer of the formation. In addition, the method comprises (b) flowing steam through the steam injection well from the consolidated layer of the formation into the unconsolidated layer of the formation. Further, the method comprises (c) injecting steam from the injection well into the unconsolidated layer of the formation.

Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:

FIG. 1 is a schematic cross-sectional side view of an embodiment of a system in accordance with the principles described herein for producing viscous hydrocarbons from a subterranean formation with steam-assisted gravity drainage techniques;

FIG. 2 is a schematic cross-sectional end view of the system of FIG. 1 taken along section 2-2 of FIG. 1;

FIG. 3 is an enlarged partial side view of a section of the liner disposed in the production well and the injection well of FIGS. 1 and 2;

FIG. 4 is a schematic cross-sectional side view of the system of FIG. 1 during SAGD production operations; and

FIG. 5 is a schematic cross-sectional end view of the system of FIG. 4 taken along section 5-5 of FIG. 4 during SAGD production operations.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.

Certain terms are used throughout the following description and claim to refer to particular system components. This document does not intend to distinguish between components that differ in name but not function. Moreover, the drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form, and some details of conventional elements may not be shown in the interest of clarity and conciseness.

In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . . ” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. Further, reference to “up” or “down” may be made for purposes of description with “up,” “upper,” “upward,” or “above” meaning generally toward or closer to the surface of the earth, and with “down,” “lower,” “downward,” or “below” meaning generally away or further from the surface of the earth. Also, as used herein, terms describing orientations such as but not limited to “horizontal” and “vertical” are not intended to denote or require absolute mathematical or geometrical precision. Accordingly, such terms are to be understood as denoting or requiring substantial precision only (e.g., “substantially horizontal”) unless the context clearly requires otherwise. Moreover, as used herein, the term “consolidated” is used to describe naturally occurring geologic materials and formations that have been lithified (turned to stone) and/or whose particles are stratified (layered), cemented, or firmly packed together (hard rock); and the term “unconsolidated” is used to described naturally occurring geologic materials and formations that have not been lithified, that comprise sediment that is loosely arranged or unstratified (not in layers), and/or whose particles are not cemented together (soft rock).

Referring now to FIGS. 1 and 2, an embodiment of a system 10 for producing viscous hydrocarbons (e.g., heavy oil and bitumen) from a subterranean formation 100 using steam-assisted gravity drainage (SAGD) techniques is schematically shown. Moving downward from the surface 5, formation 100 includes an upper layer or region 101 of consolidated cap rock, an intermediate layer or region 105 of unconsolidated sedimentary rock (e.g., McMurray sandstone), and a lower layer or region 106 of consolidated sedimentary rock (e.g., Devonian limestone). Layer 105 of unconsolidated sedimentary rock is porous, thereby enabling the storage of hydrocarbons therein and allowing the flow and percolation of fluids therethrough. In particular, layer 105 contains a reservoir 108 of viscous hydrocarbons (reservoir 108 shaded in FIGS. 1 and 2). Layers 105, 106 meet at an interface 109 in formation 100. Interface 109 extends substantially horizontally, but is not planar or perfectly horizontal as it includes some upward and downward undulations.

In this embodiment, a layer 107 of sedimentary rock (e.g., shale) extends horizontally across intermediate layer 105 and reservoir 108 therein, thereby dividing layer 105 and reservoir 108 into upper portions 105 a, 108 a, respectively, disposed between layers 101, 107 and lower portions 105 b, 108 b, respectively, disposed between layers 106, 107. In this embodiment, layer 107 is less porous than intermediate layer 105, and thus, restricts and/or prevents the flow of fluids therethrough. Accordingly, layer 107 may also be described as a “barrier” and/or “fluid impermeable” as it restricts and/or prevents fluid flow between portions 105 a, 105 b of intermediate layer 105, and restricts and/or prevents fluid flow between portions 108 a, 108 b of reservoir 108.

Referring still to FIGS. 1 and 2, system 10 mobilizes, collects and produces viscous hydrocarbons in reservoir 108 using SAGD techniques. In this embodiment, system 10 includes an steam injection well 20 extending downward from the surface 5, a hydrocarbon production well 50 extending downward from the surface 5, and a plurality of vertical ports or passages 60 extending through barrier 107 between portions 105 a, 108 a and 105 b, 108 b. For purposes of clarity, injection well 20 is represented with solid lines in FIGS. 1 and 4, production well 50 is represented with a dashed line in FIGS. 1 and 4, and passages 60 are represented with dotted lines in FIGS. 1 and 4. During production operations, steam is injected into intermediate layer 105 through well 20, viscous hydrocarbons in reservoir 108 are mobilized and drain into production well 50, and the hydrocarbons that collect in production well 50 are produced to the surface 5. Accordingly, wells 20, 30 may also be described as a “SAGD well pair.” As will be described in more detail below, passages 60 allow mobilized hydrocarbons in upper portion 105 a to flow through barrier 107 into lower portion 105 b to enhance the drainage of mobilized hydrocarbons from reservoir 108 into production well 50.

As best shown in FIG. 1, injection well 20 includes a plurality of interconnected primary bores or portions 21, 22, 23 and a plurality of secondary bores or portions 24 extending from primary portion 23. First primary portion 21 extends downward from the surface 5 into unconsolidated layer 105, second primary portion 22 extends laterally from first primary portion 21 through unconsolidated layer 105, and third primary portion 23 extends laterally from first portion 21 through consolidated layer 106. In this embodiment, first primary portion 21 extends vertically from the surface 5 through unconsolidated layer 105 to consolidated layer 106, second primary portion 22 extends horizontally through unconsolidated layer 105, and third primary portion 23 extends horizontally through consolidated layer 106. Thus, primary portions 22, 23 are oriented parallel to each other with portion 22 disposed above portion 23. Secondary portions 24 extend upward from third primary portion 23 in consolidated layer 106 through interface 109 and into unconsolidated layer 105. Thus, each secondary portion 24 has a first end 24 a coupled to third primary portion 23 and a second end 24 b disposed in unconsolidated layer 105. Although four secondary portions 24 are shown in FIG. 1, in general, any number of secondary portions (e.g., secondary portions 24) can be provided.

For purposes of clarity and further explanation, the four secondary portions 24 shown in FIG. 1 are labeled 24-1, 24-2, 24-3, 24-4. Secondary portion 24-3 is represented with a hidden dashed line in FIG. 2, however, the remaining secondary sections 24-1, 24-2, 24-4, as well as passages 60, are not shown in FIG. 2. In this embodiment, a first plurality of secondary portions 24-1, 24-2 extend upward from third primary portion 23 into unconsolidated layer 105 and then horizontally through unconsolidated layer 105. Thus, each secondary portion 24-1, 24-2 of injection well 20 includes a first section 24-1 a, 24-2 a, respectively, extending generally upward from portion 23 and the corresponding end 24 a and a second section 24-1 b, 24-2 b, respectively, extending from first section 24-1 a, 24-2 a, respectively, to the corresponding end 24 b. Second section 24-1 b of secondary portion 24-1 extends horizontally through lower portions 105 b, 108 b of unconsolidated layer 105 and reservoir 108, respectively, and is vertically disposed between primary portion 22 and barrier 107. Second section 24-2 b of secondary portion 24-2 extends horizontally through upper portions 105 a, 108 a of unconsolidated layer 105 and reservoir 108, respectively, and is positioned above barrier 107. Thus, first section 24-2 a of secondary portion 24-2 extends upward through barrier 107, while first section 24-la of secondary portion 24-1 does not extend through barrier 107. In addition, in this embodiment, a second plurality of secondary portions 24-3, 24-4 extend upward from corresponding ends 24 a and primary portion 23 through lower portions 105 b, 108 b of unconsolidated layer 105 and reservoir 108, respectively, and barrier 107 into upper portions 105 b, 108 b of unconsolidated layer 105 and reservoir 108, respectively. However, in this embodiment, secondary portions 24-3, 24-4 do not include any horizontal sections.

Referring still to FIG. 1, each secondary portion 24 of injection well 20 includes a valve 25 at first end 24 a (i.e., at the juncture with third primary portion 23). Each valve 25 has an open position allowing fluid communication between third primary portion 23 and the corresponding secondary portion 24, and a closed position preventing fluid communication between third primary portion 23 and the corresponding secondary portion 24. As will be described in more detail below, valves 25 can be independently opened or closed to selectively control the flow of steam from third primary portion 23 into one or more secondary portions 24.

Referring now to FIGS. 1 and 2, production well 50 includes a first portion 51 extending downward from the surface 5 into unconsolidated layer 105 and a second portion 52 extending laterally from first portion 51 through unconsolidated layer 105. In this embodiment, first portion 51 extends vertically from the surface 5 through unconsolidated layer 105 to a depth proximal interface 109, and second portion 52 extends horizontally through unconsolidated layer 105 proximal interface 109. In particular, second portion 52 of production well 50 is positioned in unconsolidated layer 105 at a minimum height or vertical distance D₅₂ from interface 109 and consolidated layer 106. In other words, at the closest proximity between second portion 52 and consolidated layer 106, second portion 52 is vertically spaced above consolidated layer 106 by distance D₅₂. To maximize the quantity of mobilized hydrocarbons received by production well 50 and produced to the surface 5, distance D₅₂ is preferably as small as possible. In other words, second portion 52 is preferably positioned within unconsolidated layer 105 as close as possible to consolidated layer 106. More specifically, distance D₅₂ is preferably less than 5.0 m, more preferably less than 3.0 m, and even more preferably about 1.0 m.

As shown in FIG. 1, horizontal portions 22, 23, 52 of wells 20, 50 are generally coextensive and extend in the same direction. Thus, portions 22, 23, 52 are oriented parallel to each other with portion 22 disposed above portion 52, which is disposed above portion 23. Although portions 22, 23, 52 and sections 24-1 b, 24-2 b of secondary portions 24-1, 24-2 are described as “horizontal,” depending on the location and geometry of reservoir 108, barrier 107, and interface 109, each portion 22, 23, 52 and 24-1 b, 24-2 b can be horizontal or at a slight slope (preferably less than 10°) from horizontal. Horizontal portion 22 of injection well 20 is vertically spaced above horizontal portion 52 of production well 50 by a vertical distance D₂₂₋₅₂ preferably less than 10.0 m, and more preferably less than or equal to 5.0 m. Each portion and section of wells 20, 50 preferably has a diameter between 4.0 and 12.0 in., and more preferably about 7.0 in.

As best shown in FIG. 2, in this embodiment, horizontal portions 22, 23 and horizontal sections 24-1 b, 24-2 b of injection well 20, and horizontal portion 52 of production well 50 are parallel and vertically arranged one-above-the-other. In particular, the longitudinal axes of portions 22, 23, 52 and sections 24-1 b, 24-2 b lie in a common vertical plane V₁. Thus, in this embodiment, portions 22, 23, 52 are not laterally offset or staggered relative to each other. However, in other embodiments, one or more of the horizontal portions of the injection well (e.g., portions 22, 23 and sections 24-1 b, 24-2 b of injection well 20) and production well (e.g., portion 52 of production well 50) can be laterally offset relative to one or more of the others. First sections 24-1 a, 24-2 a, 24-3 a, 24-4 a of secondary portions 24 extend upward from primary portion 23 and pass laterally adjacent portions 21, 52, and thus, do not intersect either portion 21, 52. Moreover, those secondary portions 24 that cross in side view (FIG. 1), such as secondary portions 24-1, 24-2, secondary portions 24-1, 24-3, and secondary portions 21-4, 24-4 pass laterally adjacent each other and do not intersect.

Referring to FIG. 1, each passage 60 extends vertically through barrier 107 and has a first or upper end 60 a disposed above barrier 107 in upper portion 105 a of unconsolidated layer 105 and a second or lower end 60 b disposed below barrier 107 in lower portion 105 b of unconsolidated layer 105. In this embodiment, passages 60 are coextensive, parallel, and arranged laterally side-by-side in a row extending parallel to horizontal portions 22, 23, 52 and sections 24-1 b, 24-2 b. In addition, in this embodiment, the longitudinal axes of passages 60 lie in vertical plane V₁, and, thus, passage 60 are positioned vertically in-line with horizontal portions 22, 23, 52 and sections 24-1 b, 24-2 b.

Each passage 60 is spaced from each adjacent passage 60 by a horizontal distance D₆₀₋₆₀ preferably between 5.0 and 50.0 m. In addition, each passage 60 has a diameter preferably between 3.5 and 12.0 in. Still further, each passage 60 extends to a distance D₆₀ measured vertically upward from barrier 107 to upper end 60 a. Each distance D₆₀ is preferably 1.0 to 5.0 m. Passages 60 are spaced from wells 20, 50 and do not intersection any portion or section of wells 20, 50.

In general, unconsolidated layer 105 is less stable (i.e., more prone to collapse) than consolidated layers 101, 106 and barrier 107. Accordingly, at least the portions of wells 20, 50 and passages 60 extending through unconsolidated layer 105 are preferably lined or cased to maintain and ensure integrity. As will be described in more detail below, steam injection well 20 transports steam downhole from the surface 5 and injects the steam into unconsolidated layer 105 to transfer thermal energy to and mobilize the viscous hydrocarbons in reservoir 108, and production well 50 receives and collects the mobilized hydrocarbons that drain/flow downward through unconsolidated layer 105 under the force of gravity. The mobilized hydrocarbons collected in production well 50 are then produced to the surface 5. Accordingly, the portions of injection well 20 designed to inject steam into unconsolidated layer 105, and the portion of production well 50 designed to receive and collect mobilized hydrocarbons from unconsolidated layer 105 are preferably lined with a slotted or perforated liner that allows fluid communication between layer 105 and the inside of well 20, 50. However, the portions of injection well 20 that are not designed to inject steam into formation 100, and the portions of production well 50 that are not designed to receive or collect mobilized hydrocarbons from layer 105 are preferably cased (i.e., lined with a solid tubular that does not include any slots or perforations). In this embodiment, primary portion 21 and sections 24-1 a, 24-2 a of secondary portions 24-1, 24-2, respectively, of injection well 20, and portion 51 of production well 50 are lined with casing 70; and primary portion 22, secondary portions 24-3, 24-4, and sections 24-1 b, 24-2 b of secondary portions 24-1, 24-2, respectively, of injection well 20, and horizontal portion 52 of production well 50 are lined with slotted liners 71. Primary portion 23 of injection well 20 extends through consolidated layer 106, which is generally stable and fluid impermeable. Thus, primary portion 23 can be lined with casing (e.g., casing 70), a slotted liner (e.g., liner 71), or left unlined (i.e., without casing 70 and liner 71).

As will be described in more detail below, passages 60 receive the mobilized hydrocarbons that drain/flow through downward through upper portion 105 a under the force of gravity, flow the mobilized hydrocarbons downward through barrier 107, and release the mobilized hydrocarbons into lower portion 105 b. Accordingly, each passage 60 is lined with a slotted liner 71 that extends between ends 60 a, 60 b and allows fluid communication between portions 105 a, 105 b of unconsolidated layer 105 and the inside of the corresponding passage 60. In general, the upper and lower ends of liners 71 in passages 60 disposed at ends 60 a, 60 b, respectively, can be open or closed. In this embodiment, the ends of liners 71 in passages 60 are open to allow fluid flow through ends 60 a, 60 b.

As best shown in FIG. 3, one slotted liner 71 is shown it being understood that each slotted liner 71 is configured similarly. Each slotted liner 71 includes a plurality of uniformly circumferential and axially spaced holes of slots 72. In general, slots 72 may be limited to specific locations along each liner 71. In this embodiment, slots 72 are provided along the entire length of each liner 71 disposed in horizontal portions 22, 52, horizontal sections 24-1 b, 24-2 b, secondary portions 24-3, 24-4, and passages 60. Thus, liners 71 disposed in horizontal portions 22, 23, 52 includes slots 72 along their entire lengths; liners 71 disposed in horizontal sections 24-1 b, 24-2 b of secondary portions 24-1, 24-2, respectively, include slots 72 along their entire lengths; liners 71 disposed in secondary portions 24-3, 24-4 include slots 72 along their entire lengths; and liners 71 disposed in passages 60 include slots 72 along their entire lengths. Each liner 71 extending through barrier 107 (i.e., liners 71 disposed in passages 60 and liners 71 disposed in secondary portions 24-3, 24-4) includes a plurality of slots 72 positioned immediately above barrier 107 and a plurality of slots 72 are positioned immediately below barrier 107.

Referring still to FIG. 1, in general, system 10 can be constructed by forming wells 20, 50, and passages 60 in any desired sequence or in parallel, and further, wells 20, 50 and passages 60 can be formed by any suitable means known in the art. Due to the various deviations in wells 20, 50, wells 20, 50 are formed via directional drilling techniques. In this embodiment, injection well 20 is formed before production well 50 as formation of secondary portions 24 of injection well 20 facilitate the desired positioning of second portion 52 of production well 50 in unconsolidated layer 105 as close as possible to interface 109 (i.e., at distance D₅₂). In particular, primary portion 21 is drilled from the surface 5 to the desired depth in formation 100, and then, primary portions 22, 23 are drilled laterally from primary bore 21 (at the desired depths) through unconsolidated layer 105 and consolidated layer 106, respectively. Next, secondary portions 24 are drilled from primary portion 23 into unconsolidated layer 105—secondary portion 24-1 is not drilled through barrier 107, while secondary portions 24-2, 24-3, 24-4 are drilled through barrier 107. Casing 70 and liners 71 can be run into injection well 20 during or after drilling well 20.

As shown in FIG. 1, secondary portions 24 cross interface 109, and thus, logging data acquired while drilling secondary portions 24 is used to map out the position and geometry of interface 109. By better understanding the actual location of interface 109 (via the drilling logs) prior to forming horizontal portion 52 of injection well 50, horizontal portion 52 can be positioned within unconsolidated layer 105 closer to interface 109 with greater confidence.

After formation of injection well 20 and identification of the location of interface 109 via drilling logs, injection well 50 is formed. In particular, first portion 51 is drilled from the surface 5 to the desired depth in formation 100, and then, second portion 52 is drilled laterally from first portion 51 through unconsolidated layer 105. As previously described, mapping out the actual location of interface 109 via drilling logs from the drilling of secondary portions 24 of injection well 20, horizontal portion 52 can be positioned (with confidence) within unconsolidated layer 105 much closer to interface 109 than if the actual position of interface 109 was not mapped out and is estimated solely based on seismic data. Casing 70 and liners 71 can be run into production well 50 during or after drilling well 50.

In general, passages 60 can be formed before, during, or after formation of one or both of wells 20, 50. Further, passages 60 can be formed by drilling downward from the surface 5 through barrier 107 or drilling upward from injection well 20 or production well 50 through barrier 107 by any suitable drilling technique known in the art. In either case, the drilled boreholes will have lengths much longer than passages 60 shown in FIG. 1 (i.e., the drilled boreholes will extend to the surface 5, injection well 20, or production well 50). However, liners 71 are run into the drill boreholes and positioned between ends 60 a, 60 b-only those portions of the drilled boreholes that define passages 60 are lined. Thus, the remaining portions of the drilled boreholes extending through unconsolidated layer 105 will collapse and close, resulting in passages 60 having ends 60 a, 60 b defined by the upper and lower ends of liners 71 disposed therein.

Referring now to FIGS. 4 and 5, the operation of system 10 to produce viscous hydrocarbons (e.g., bitumen and/or heavy oil) in reservoir 108 is schematically shown. More specifically, steam is pumped from the surface 5 through injection well 20 and injected into layer 105 and reservoir 108 therein. In particular, the steam flows down vertical primary portion 21 and through each horizontal primary portion 22, 23. The steam in horizontal portion 22 is injected into lower portion 105 b of unconsolidated layer 105 (and lower portion 108 b of reservoir 108 therein) below barrier 107 via slots 72 in liner 71 disposed within portion 22. The steam and associated hot water injected from primary portion 22 percolate through lower portion 105 b, thereby forming a steam chamber 110 that extends horizontally outward and vertically upward from portion 22 to barrier 107. Thus, steam chamber 110 is generally shaped like an inverted triangular prism that extends upward from and along the entire length of portion 22 of injection well 20. Steam chamber 110 does not extend through barrier 107 as barrier 107 is generally fluid impermeable, and thus, restricts and/or prevents the passage of steam therethrough.

Horizontal primary portion 23 of injection well 20 is disposed in consolidated layer 106, which is generally fluid impermeable, and thus, regardless of whether portion 23 is uncased, cased, or lined with a slotted liner, portion 23 does not inject steam into unconsolidated layer 105 or reservoir 108. Rather, portion 23 transports steam to one or more secondary portions 24, which injects steam into unconsolidated layer 105 and reservoir 108. In particular, steam flows from primary portion 23 into each secondary portion 24 with its corresponding valve 25 in the open position, but is prevented from flowing into each secondary portion 24 with its corresponding valve 25 in the closed position. Thus, by independently controlling the positions of valves 25, steam can be directed to any one or more secondary portions 24 as desired. In addition, by independently controlling the positions of valves 25, the volumetric flow rate of steam directed to any one or more secondary portions 24 can be adjusted as desired to target specific areas of layer 105 and reservoir 108. More specifically, for a given volumetric flow rate of steam into primary portion 23, the volumetric flow rate of steam into any one secondary portion 24 can be increased by closing the valve(s) 25 of one or more other secondary portions 24, and decreased by closing the corresponding valve 25 or opening the valve(s) 25 of one or more other secondary portions 24. In general, the volumetric flow rate of steam flowing into and through a given secondary portion 24 is directly related to the volume of steam injected into unconsolidated layer 105 from that secondary portion 24. Thus, the greater the volumetric flow rate of steam flowing into and through into a given secondary portion 24, the greater the volume of steam injected into unconsolidated layer 105 from that secondary portion 24; and the lower the volumetric flow rate of steam flowing into and through a given secondary portion 24, the lower the volume of steam injected into unconsolidated layer 105 from that secondary portion 24. In FIGS. 4 and 5, system 10 is illustrated with each valve 25 in the open position, and thus, steam flows from primary portion 23 into each secondary portion 24. However, it should be appreciated that any one or more of valves 25 can be closed to selectively flow steam into and through one or more secondary portions 24 and/or to adjust the volumetric flow rate of steam into any one or more secondary portions 24.

Referring still to FIGS. 4 and 5, as previously described, sections 24-1 a, 24-2 a of secondary portions 24-1, 24-2, respectively, are lined with casing 70; whereas sections 24-1 b, 24-2 b of secondary portions 24-1, 24-2, respectively, and secondary portions 24-3, 24-4 are lined with slotted liners 71. Thus, steam flowing through horizontal section 24-1 b is injected into lower portion 105 b of unconsolidated layer 105 (and lower portion 108 b of reservoir 108 therein) below barrier 107 via slots 72 in liner 71 disposed within section 24-1 a; steam flowing through horizontal section 24-2 b is injected into upper portion 105 a of unconsolidated layer 105 (and upper portion 108 a of reservoir 108 therein) above barrier 107 via slots 72 in liner 71 disposed within section 24-2 b; steam flowing through secondary portion 24-3 is injected into upper and lower portion 105 a, 105 b of unconsolidated layer 105 (and upper and lower portions 108 a, 108 b of reservoir 108 therein) above and below barrier 107, respectively, via slots 72 in liner 71 disposed within secondary portion 24-3; and steam flowing through secondary portion 24-4 is injected into upper and lower portion 105 a, 105 b of unconsolidated layer 105 (and upper and lower portions 108 a, 108 b of reservoir 108 therein) above and below barrier 107, respectively, via slots 72 in liner 71 disposed within secondary portion 24-4.

The steam and associated hot water injected from section 24-1 b percolate through lower portion 105 b, thereby forming a steam chamber 111 that extends horizontally outward and vertically upward from section 24-1 b to barrier 107; and the steam and associated hot water injected from section 24-2 b percolate through upper portion 105 a, thereby forming a steam chamber 112 that extends horizontally outward and vertically upward from section 24-2 b to consolidated layer 101. Thus, each steam chamber 111, 112 is generally shaped like an inverted triangular prism that extends upward from and along the entire length of section 24-1 b, 24-2 b, respectively, of injection well 20. Steam chambers 111, 112 do not extend through barrier 107 or layer 101, respectively, as barrier 107 and layer 101 are generally fluid impermeable, and thus, restricts and/or prevents the passage of steam therethrough. The steam and associated hot water injected from portion 24-3 into lower portion 105 b percolate through lower portion 105 b, thereby forming a steam chamber 113 that extends horizontally outward and vertically upward from portion 24-3 to barrier 107; and the steam and associated hot water injected from portion 24-3 into upper portion 105 a percolate through upper portion 105 a, thereby forming a steam chamber 114 that extends horizontally outward and vertically upward from portion 24-3. Thus, steam injected into layer 105 from secondary portion 24-3 forms two steam chambers 113, 114 on opposite sides of barrier 107; neither steam chamber 113, 114 extends through barrier 107 as barrier 107 is generally fluid impermeable. Steam chamber 113 has a generally conical shape, and steam chamber 114 has a generally dome or hemispherical shape. Similarly, the steam and associated hot water injected from portion 24-4 into lower portion 105 b percolate through lower portion 105 b, thereby forming a steam chamber 115 that extends horizontally outward and vertically upward from portion 24-4 to barrier 107; and the steam and associated hot water injected from portion 24-4 into upper portion 105 a percolate through upper portion 105 a, thereby forming a steam chamber 116 that extends horizontally outward and vertically upward from portion 24-4. Thus, steam injected into layer 105 from secondary portion 24-4 forms two steam chambers 115, 116 on opposite sides of barrier 107; neither steam chamber 115, 116 extends through barrier 107 as barrier 107 is generally fluid impermeable. Steam chamber 115 has a generally conical shape, and steam chamber 116 has a generally dome or hemispherical shape. Steam chambers 110, 111, 112, 113, 114, 115, 116 are shown in FIG. 4; and steam chambers 110, 111, 113, 114 are shown in FIG. 5 (steam chambers 113, 114 are shown in phantom in FIG. 5).

In the manner described, primary portion 23 and secondary portions 24 extending therefrom facilitate the distribution of steam within unconsolidated layer 105 above and below barrier 107. In addition, as compared to a conventional injection well having a single horizontal bore for steam injection, primary portion 23 and secondary portions 24 enhance steam distribution in unconsolidated layer 105 by forming a plurality of steam chambers 111, 113, 115 in lower portion 105 b of unconsolidated layer 105 below barrier 107, and allowing steam to pass through barrier 107 to form a plurality of steam chambers 112, 114, 116 in unconsolidated layer 105 above barrier 107.

As best shown in FIG. 4, a portion of the steam in chambers 110, 111, 113, 115 migrates into passages 60 and slotted liners 71 disposed therein via slots 72 positioned below barrier 107. The steam then flows upward within passages 60 and liners 71 through barrier 107, and is injected into upper portion 105 a above barrier 107 via slots 72 in liners 71 positioned above barrier 107. The steam injected into upper portion 105 a from passages 60, as well as associated hot water, percolate through upper portion 105 a above barrier 107, thereby forming a plurality of steam chambers 117. Each steam chamber 117 extends radially/laterally outward and vertically upward from slotted liners 71 extending upward from barrier 107. Thus, each steam chamber 117 has a generally domed or hemispherical shape. In this embodiment, passages 60 are horizontally/laterally spaced sufficiently close together that each chamber 117 intersects each adjacent chamber 117, thereby forming a continuous steam chamber 118 extending through upper portion 105 a above barrier 107 generally parallel to chambers 110, 111. Steam chambers 117, 118 are shown in FIGS. 4 and 5 (shown in phantom in FIG. 5).

In the manner described, passages 60 extending through barrier 107 and slotted liners 71 disposed therein facilitate the distribution of steam within unconsolidated layer 105 above barrier 107. In addition, as compared to a conventional injection well having a single horizontal run for steam injection, passages 60 and slotted liners 71 disposed therein enhance steam distribution in unconsolidated layer 105, allowing steam to pass through and above barrier 107 to form steam chambers 117, 118 in upper portion 105 a of unconsolidated layer 105 above barrier 107.

Referring still to FIGS. 4 and 5, thermal energy from steam chambers 112, 114, 116, 117, 118 reduces the viscosity of the viscous hydrocarbons in upper portion 108 a of reservoir 108 to a sufficient extent to allow them to flow under the force of gravity downward through upper portion 105 a of unconsolidated layer 105. Barrier 107 substantially blocks the continued downward flow of the viscosity-reduced (i.e., mobilized) hydrocarbons in upper portion 105 a. However, the mobilized hydrocarbons in upper portion 105 a flow into passages 60 and corresponding slotted liners 71 via slots 72 disposed above barrier 107, and then downward through barrier 107. The hydrocarbons passing through barrier 107 exit passages 60 and corresponding slotted liners 71 into lower portion 105 b of unconsolidated layer 105 via slots 72 disposed below barrier 107.

Thermal energy from steam chambers 110, 111, 113, 115 reduces the viscosity of the viscous hydrocarbons in lower portion 108 b of reservoir 108 to a sufficient extent to allow them to flow under the force of gravity downward through lower portion 105 b of unconsolidated layer 105. In addition, thermal energy from steam chambers 110, 111, 113, 115 reduces the viscosity and/or maintains the reduced viscosity of mobilized hydrocarbons exiting passages 60 and slotted liners 71 disposed therein into lower portion 105 b and allows them to flow under the force of gravity downward through lower portion 105 b of layer 105. The mobilized hydrocarbons in lower portion 105 b drain into horizontal portion 52 of production well 50 via slots 72 in the slotted liner 71 disposed in portion 52. The hydrocarbons collect in production well 50, and are produced to the surface 5 via artificial lift (e.g., pumps).

While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps. 

What is claimed is:
 1. A system for recovering hydrocarbons from a subterranean formation with steam-assisted gravity drainage (SAGD), the formation including an unconsolidated layer containing a hydrocarbon reservoir and a consolidated layer disposed below the unconsolidated layer, the system comprising: a steam injection well including a first portion extending from the surface through the unconsolidated layer to the consolidated layer, a second portion extending horizontally through the consolidated layer, and at least one third portion extending from the second portion, wherein each third portion extends upward from the second portion into the unconsolidated layer of the formation and the hydrocarbon reservoir; a production well including a first portion extending from the surface through the unconsolidated layer and a second portion extending horizontally through the unconsolidated layer, wherein the second portion of the production well is vertically positioned above the second portion of the steam injection well.
 2. The system of claim 1, wherein the second portion of the production well is disposed in the unconsolidated layer proximal the consolidated layer.
 3. The system of claim 2, wherein the second portion of the production well is disposed at a minimum height H measured vertically from an interface between the consolidated layer and the unconsolidated layer, wherein the minimum height H is less than 5.0 meters.
 4. The system of claim 3, wherein the minimum height H is about 1.0 meter.
 5. The system of claim 1, wherein the steam injection well includes a fourth portion extending horizontally through the unconsolidated layer, wherein the fourth portion of the steam injection well is vertically positioned above the second portion of the production well.
 6. The system of claim 1, wherein the formation includes a fluid impermeable barrier disposed within the unconsolidated layer; wherein an upper portion of the hydrocarbon reservoir is disposed above the fluid impermeable barrier and a lower portion of the hydrocarbon reservoir is disposed below the fluid impermeable barrier; wherein the second portion of the injection well and the second portion of the production well are positioned below the fluid impermeable barrier; wherein at least one of the third portions of the steam injection well extends upward through the fluid impermeable barrier and is configured to transport steam from the second portion of the steam injection well to the upper portion of the hydrocarbon reservoir.
 7. The system of claim 6, further comprising a passage extending through the fluid impermeable barrier, wherein the passage has an upper end disposed in the unconsolidated layer above the fluid impermeable barrier and a lower end disposed in the unconsolidated layer below the fluid impermeable barrier.
 8. The system of claim 7, wherein a slotted liner is disposed in the passage and a slotted liner is disposed in each of the third portions of the steam injection well that extend upward through the fluid impermeable barrier.
 9. The system of claim 8, wherein each slotted liner comprises: a first plurality of slots positioned above the fluid impermeable barrier; and a second plurality of slots positioned below the fluid impermeable barrier.
 10. The system of claim 7, wherein the passage is configured to transport hydrocarbons from the unconsolidated layer above the fluid impermeable barrier to the unconsolidated layer below the fluid impermeable barrier.
 11. The system of claim 10, wherein the passage is configured to transport steam from the unconsolidated layer below the fluid impermeable barrier to the unconsolidated layer above the fluid impermeable barrier.
 12. The system of claim 1, further comprising a valve disposed along each third portion of the steam injection well proximal the second portion of the steam injection well; wherein each valve has an open position allowing fluid communication between the second portion of the steam injection well and the corresponding third portion of the steam injection well, and a closed position preventing fluid communication between the second portion of the steam injection well and the corresponding third portion of the steam injection well.
 13. A method for producing hydrocarbons from a subterranean formation with steam-assisted gravity drainage (SAGD), the formation including an unconsolidated layer containing a hydrocarbon reservoir and a consolidated layer disposed below the unconsolidated layer, the method comprising: (a) drilling a first portion of a steam injection well through the consolidated layer of the formation; (b) drilling a plurality of second portions of a steam injection well upward from the first portion of the steam injection well into the unconsolidated layer; (c) drilling a first portion of a production well through the unconsolidated layer of the formation.
 14. The method of claim 13, further comprising: (d) flowing steam through the first portion of the steam injection well to the second portions of the steam injection well; (e) flowing steam from the first portion of the steam injection well into at least one of the second portions of the steam injection well during (d); and (f) injecting steam from the at least one of the second portions of the steam injection well into the unconsolidated layer of the formation during (e).
 15. The method of claim 14, further comprising: (g) reducing the viscosity of the hydrocarbons and flowing the hydrocarbons through the unconsolidated layer into the first portion of the production well; and (h) producing the hydrocarbons in the first portion of the production well to the surface.
 16. The method of claim 14, further comprising: selectively preventing the flow of steam from the first portion of the steam injection well into one or more of the second portions of the steam injection well.
 17. The method of claim 13, wherein (b) comprises: drilling at least one of the second portions of the steam injection well upward through a fluid impermeable barrier extending through the unconsolidated layer of the formation; wherein an upper portion of the unconsolidated layer is disposed above the fluid impermeable barrier and a lower portion of the unconsolidated layer is disposed below the fluid impermeable barrier; wherein an upper portion of the hydrocarbon reservoir is disposed above the fluid impermeable barrier and a lower portion of the hydrocarbon reservoir is disposed below the fluid impermeable barrier.
 18. The method of claim 17, further comprising: drilling a passage through the fluid impermeable barrier.
 19. The method of claim 17, further comprising: (d) flowing steam through the first portion of the steam injection well to the second portions of the steam injection well; (e) flowing steam from the first portion of the steam injection well into at least one of the second portions of the steam injection well during (d); and (f) flowing steam upward in the at least one of the second portions of the steam injection well through the fluid impermeable barrier during (e); and (g) injecting steam from the at least one of the second portions of the steam injection well into the upper portion of the hydrocarbon reservoir.
 20. The method of claim 18, further comprising: (d) flowing steam through the first portion of the steam injection well to the second portions of the steam injection well; (e) flowing steam from the first portion of the steam injection well into at least one of the second portions of the steam injection well during (d); and (f) flowing steam upward in the at least one of the second portions of the steam injection well through the fluid impermeable barrier during (e); (g) injecting steam from the at least one of the second portions of the steam injection well into the upper portion of the hydrocarbon reservoir; (h) flowing hydrocarbons from the upper portion of the hydrocarbon reservoir through the passage into the lower portion of the unconsolidated layer.
 21. The method of claim 20, further comprising: flowing hydrocarbons from the passage through the lower portion of the unconsolidated layer into the first portion of the production well; and flowing hydrocarbons through the first portion of the production well to the surface.
 22. The method of claim 13, further comprising: drilling each second portion of the steam injection well upward across an interface between the consolidated layer and the unconsolidated layer; identifying a location where each second portion crosses the interface while drilling each second portion; utilizing the locations where the second portions cross the interface to determine the location of the first portion of the production well within the unconsolidated layer.
 23. A method for producing hydrocarbons from a subterranean formation with steam-assisted gravity drainage (SAGD), the formation including an unconsolidated layer containing a hydrocarbon reservoir and a consolidated layer disposed below the unconsolidated layer, the method comprising: (a) flowing steam from the surface through a subterranean steam injection well extending through the unconsolidated layer of the formation and into the consolidated layer of the formation; (b) flowing steam through the steam injection well from the consolidated layer of the formation into the unconsolidated layer of the formation; and (c) injecting steam from the injection well into the unconsolidated layer of the formation.
 24. The method of claim 23, further comprising: (d) flowing hydrocarbons from the hydrocarbon reservoir into a portion of a production well extending through the unconsolidated layer of the formation; and (e) producing hydrocarbons in the production well to the surface.
 25. The method of claim 24, wherein a fluid impermeable barrier extends through the unconsolidated layer of the formation and divides the hydrocarbon reservoir into a lower portion disposed below the fluid impermeable barrier and an upper portion disposed above the fluid impermeable barrier; wherein (b) further comprises flowing steam through the injection well and the fluid impermeable barrier; wherein (c) further comprises injecting steam from the injection well into the upper portion of the hydrocarbon reservoir.
 26. The method of claim 25, further comprising: (f) flowing hydrocarbons downward through a passage in the fluid impermeable barrier.
 27. The method of claim 23, wherein the injection well includes a first portion extending horizontally through the consolidated layer of the formation and a plurality of second portions extending from the first portion into the unconsolidated layer of the formation.
 28. The method of claim 27, wherein at least one of the second portions extends through a fluid impermeable barrier in the unconsolidated layer of the formation, wherein the fluid impermeable barrier divides the hydrocarbon reservoir into a lower portion disposed below the fluid impermeable barrier and an upper portion disposed above the fluid impermeable barrier.
 29. The method of claim 27, further comprising: drilling each second portion from the first portion across an interface between the consolidated layer and the unconsolidated layer; identifying a location where each second portion crosses the interface while drilling each second portion; utilizing the locations where each second portion crosses the interface to position a horizontal portion of a production well extending from the surface through the unconsolidated layer of the formation. 